Method of heating hydrocarbons

ABSTRACT

The present invention relates generally to a method and means of injecting hot fluids into a hydrocarbon formation using a combustion and steam generating device installed at or near the well-head of an injector well. The various embodiments are directed generally to substantially increasing energy efficiency of thermal recovery operations by efficiently utilizing the energy of the combustion products and waste heat from the generator. The generator apparatuses can be installed at the well-head which, in turn, can be located close to the producing formation. The combustion products may be injected into a well along with steam or sequestered at another location.

CROSS REFERENCE TO RELATED APPLICATION

The present application is a divisional application of U.S. applicationSer. No. 11/864,011, filed Sep. 28, 2007, entitled “Method of HeatingHydrocarbons” which claims the benefits, under 35 U.S.C. §119(e), ofU.S. Provisional Application Ser. No. 60/827,608 filed Sep. 29, 2006,entitled “Method of Heating Hydrocarbons” to Brock, Donnelly, Kobler,Squires and Watson which is incorporated herein by these references.

Cross reference is made to U.S. patent application Ser. No. 11/737,578filed Apr. 19, 2006 entitled “Method of Drilling from a Shaft” and U.S.patent application Ser. No. 11/441,929 filed May 25, 2006, entitled“Method for Underground Recovery of Hydrocarbons”, both of which arealso incorporated herein by this reference.

FIELD

The present invention relates generally to a method and means ofinjecting hot fluids into a hydrocarbon formation using a combustion andsteam generating device installed at or near the well-head of aninjector well.

BACKGROUND

Oil is a nonrenewable natural resource having great importance to theindustrialized world. The increased demand for and decreasing suppliesof conventional oil has led to the development of alternate sources ofoil such as deposits of heavy crude and bitumen and to a search for moreefficient methods for recovery from such hydrocarbon deposits.

Examples of efficient method for recovery methods of unconventional oildeposits are the Steam Assisted Gravity Drain (“SAGD”) process whichuses steam as the fluid injected into the hydrocarbon formation and theVAPEX process which uses a diluent as the fluid injected into thehydrocarbon formation. In both methods, horizontal well pairs aretypically installed at the bottom of a heavy oil or bitumen reservoir. Awell pair is typically comprised of a first well which may be a steam ordiluent injector well and a second well which may be a fluid collectorwell. The horizontal portion of the injector well is commonly installedabove the producer well, separated by about 1 to about 5 meters. Amobilizing fluid is introduced into the injector well and injected intothe heavy oil or bitumen formation where it is used to heat or dilutethe heavy oil or bitumen in order to mobilize (reduce its viscosity) andallow the hydrocarbon to flow more readily (such as the case for heavycrude) or flow at all (the case for bitumen which is normally an in-situsolid).

When steam is used as the injected fluid, it is typically generated in alarge boiler on the surface and is typically transmitted by an insulatedpiping system to a manifold feeding six or eight near-by wells forinjection into the formation. The injected steam must travel from thesurface down to a horizontal section of the well in the hydrocarbondeposit where it is forced by pressure into the formation through manynarrow slits in the horizontal portion of the well pipe.

The SAGD method has been applied to heavy oil and bitumen recovery withvarying degrees of success, both in terms of total recovery factor andeconomics. A SAGD operation may be characterized by its Steam-Oil-Ratio(“SOR”) which is a measure of how much steam is used to recover a barrelof heavy oil or bitumen (the SOR is determined by the number of barrelsof water required to produce the steam divided by the number of barrelsof oil or bitumen recovered). Thus, an SOR of 3 means that 3 barrels ofwater are required to be injected as steam to recover 1 barrel of oil orbitumen). This ratio is often determined by geological factors withinthe reservoir and therefore may be beyond the control of the operator.Examples of these geological factors are clay, mudstone or shale lensesthat impede the migration of steam upwards and the flow of mobilized oildownwards; or thief zones comprised of lenses of formation waters. Anacceptable SOR may be in the range of 2 to 3 whereas an uneconomical SORis commonly 3 or higher. In addition to good reservoir geology, a lowSOR reflects good energy efficiency in the use of steam. If steam couldbe generated and delivered to the formation at significantly higherefficiencies than is currently achieved, then SAGD operationscharacterized by high average SOR would become more economically viable,even if the geology of the reservoir remains non-optimal.

In current practice, steam is generated in a large boiler or boilerslocated on the surface. Boilers powered by natural gas, for example,have efficiencies in the range of about 75% to 90%. The remainder of theenergy consumed by the boiler is typically scrubbed and released intothe atmosphere as flue gases. These flue gases not only add to local airpollution and greenhouse gases but represent lost energy. The generatedsteam typically loses an additional 10% to 20% of its energy as it istransmitted from the boiler downhole to the horizontal section of theSAGD injectors. For example, if a boiler is 80% efficient and there arean additional 15% transmission losses, then only 68% of the fuel energyconsumed by the boiler is delivered into the formation in the form ofhot steam. Some of the remaining 32% of waste energy may be used togenerate electrical energy by any number of co-generation methods.

Another technology proposed for recovery of hydrocarbons, includingheavy oil and bitumen, is based on mining for access to the producingformation. For example, a system of underground shafts and tunnels hasbeen proposed to allow wells to be installed from under or from within areservoir. This approach overcomes a number of problems such as surfaceaccess, product lifting difficulties and reliability of downhole pumps.In these mining for access technologies, the wellhead and its associatedequipment is readily accessible and is typically in close proximity tothe formation. Also, the wells are installed from the undergroundworkspace either horizontally or inclined upwards. A discussion of thesemining for access methods can be found in U.S. patent application Ser.No. 11/737,578 filed Apr. 19, 2006 entitled “Method of Drilling from aShaft” and U.S. patent application Ser. No. 11/441,929 filed May 25,2006, entitled “Method for Underground Recovery of Hydrocarbons”.

Installing wells from an underground workspace opens up possibilitiesfor improving steam generation efficiencies. For example, the steamboilers may be installed underground, shortening the transmissiondistances and thereby reducing transmission losses. The combustionproducts from these boilers may be captured and injected into theproducing formation or into an underground sequestering repository ifthe geology is favorable.

Reference 1 (“Thermal Recovery of Oil and Bitumen” by Roger M. Butler)describes several methods and devices for downhole (located in the wellitself) steam generation including devices that inject their products ofcombustion into the formation along with steam. If these devices areinstalled downhole near the entrance to the horizontal injectionsection, then they are difficult to service because they have to bewithdrawn to the surface or they can cause a production shut down ifthey fail while in service. If these devices are installed on thesurface at the well-head, then they are subject to transmission lossesin the portion of the well connecting the surface to the undergroundhorizontal. Additionally, these devices are generally not be able togenerate sufficient power to produce the quantity and quality of steamrequired for a stimulation of a SAGD well that may produce severalhundred barrels of oil per day.

There remains, therefore, a need for a method and system to: (1) reduceor eliminate the energy losses from the process of energizing andtransmitting the injection fluids; (2) eliminating greenhouse gasemissions; and (3) maintain the ability to rapidly service or replacesteam generation equipment without disrupting well injection andproduction operations. There also remains a need for large horsepowersteam generators that can utilize untreated water and utilize technologythat can reduce capital costs of the steam generating function.

SUMMARY

These and other needs are addressed by the present inventions. Thevarious inventions are directed generally to substantially increasingenergy efficiency of thermal recovery operations by utilizing the energyof the combustion products while simultaneously sequestering themunderground.

In a first invention, a method for recovering a hydrocarbon from anunderground hydrocarbon-containing material is provided that includesthe steps:

(a) in a manned excavation positioned in proximity to thehydrocarbon-containing material, generating a heated hydrocarbonproduction fluid;

(b) introducing, via a wellhead positioned in the manned excavation, theheated hydrocarbon production fluid into the hydrocarbon-containingmaterial to mobilize at least part of the hydrocarbons in thehydrocarbon-containing material; and

(c) thereafter recovering the mobilized hydrocarbon from thehydrocarbon-containing material.

In one configuration, each well-head has its own steam generator, andthe steam generator is capable of simulating a substantial zone of theformation by steam stimulation and/or flooding.

In one configuration, the heated hydrocarbon production fluid is steam,the wellhead is positioned adjacent to a liner of the manned excavation,an injection well passes from the wellhead, through the liner, and intothe hydrocarbon-containing material, and the generating step (a) isperformed by a steam generating device positioned in the mannedexcavation.

Waste heat from the steam generating device can be used to preheat atleast a portion of input water to the device. In one configuration, aheat exchanger is used to transfer heat from the engine to pre-heatwater prior to converting it to steam and injecting it into thehydrocarbon-containing material. In one configuration, a heat exchangeris used to transfer waste heat energy from the compressor to the waterprior to converting it to steam and injecting it into thehydrocarbon-containing material.

An exhaust gas of the steam generating device can be combined with theproduction fluid and introduced into the hydrocarbon-containing materialin step (b).

The steam generating device is commonly positioned at a distance of nomore than about 20 meters from the wellhead and a distance of no morethan about 200 meters from the hydrocarbon-containing material. In someapplications, the manned excavation is at least about 150 meters fromthe heated formation to comply with safety regulations.

The wellhead can include a controllable wellhead apparatus. Theapparatus includes a first input for the heated hydrocarbon productionfluid, a second input for a heated gaseous exhaust products, a thirdinput for water, and a manifold in communication with the first, second,and third inputs to introduce, in step (b), a mixture of the heatedhydrocarbon production fluid, heated gaseous exhaust products carbonoxide, and water into the hydrocarbon-containing material. Separateprovisions may be made for adding other gaseous products such as carbondioxide and additional water into the wellhead apparatus, for examplefor well servicing.

In a second invention, a hydrocarbon production system is provided thatincludes:

(a) a manned excavation positioned in proximity to ahydrocarbon-containing material;

(b) a generating device, positioned in the manned excavation, operableto generate a heated hydrocarbon production fluid;

(c) an injection well comprising a wellhead, the wellhead beingpositioned in the manned excavation and the injection well extendingfrom the manned excavation, the injection well being operable tointroduce the heated hydrocarbon production fluid into thehydrocarbon-containing material to mobilize at least part of thehydrocarbons in the hydrocarbon-containing material; and

(c) a collector well operable to recover the mobilized hydrocarbon fromthe hydrocarbon-containing material.

The generating device can have many different configurations. Forexample, the generator may be a robust burner device, such as known inthe art, that burns any of a number of gaseous, liquid or solid fuelspropellants and can work at reasonably high injection pressures. In yetanother configuration, the generator may be a robust device that burnsany of a number of liquid propellants and can work at much higherinjection pressures than, for example a diesel engine, and therefore beapplied to formations at pressures as high as about 50,000 psi.

These gas and/or steam generators can be installed in or near thewellhead. Their combustion products can be directed into the injectionwell along with steam. The generators can utilize essentially all theenergy of combustion to heat the heavy oil or bitumen deposit, thusconverting almost all of the generated energy into energy delivered intothe formation. Further, the generators can dispose of the combustionproducts by sequestering most or all of them in the reservoir pore spacefrom which heavy oil or bitumen has been displaced and recovered by thecollector wells. Even further, the generators can eliminate asignificant SAGD steam generation problem. The generators can besubstantially unaffected by precipitation and scaling problems common tosteam boilers and steam transmission piping and thus can minimize oreliminate the need for water treatment. The generators can be locatedvery near the horizontal section of injector well and readily servicedor replaced while maintaining the well at pressure and temperature.Servicing or replacing well-head components can be accomplished in avery short time so that production is not interrupted and thetemperature in the injector well can be maintained at a level at whichthe bitumen remains fluid in the injector well. The generators can allowfull control over injection fluid pressure and temperatures, which isnot possible with injection wells operated from the surface. Finally,when the gas and/or steam generators is located undergroundapproximately at the level of the reservoir, it can utilize asubstantial pressure head for injection fluids stored on the surface.

In a third invention, a hydrocarbon production system is provided thatincludes:

(a) a diesel engine;

(b) a compressor;

(c) a drive shaft interconnecting the diesel engine to the compressor;and

(d) a conduit transporting an exhaust gas of the diesel engine to thecompressor for injection, by an injection well, into ahydrocarbon-containing material to mobilize the hydrocarbons.

A heat exchanger can be used to transfer heat from the engine topre-heat water prior to converting it to steam and injecting it into thehydrocarbon-containing material.

In a fourth invention, a hydrocarbon production method includes thesteps:

(a) operating a diesel engine to produce an exhaust gas comprisingcarbon oxides and a rotating drive shaft;

(b) operating a compressor, by the rotating drive shaft, to form acompressed gas, the compressed gas comprising at least part of theexhaust gas from the diesel engine; and

(c) introducing the compressed gas into a hydrocarbon-containingmaterial to mobilize the hydrocarbons for production.

In one configuration, the generator is based on a diesel engine wherethe load on the diesel engine is provided by the work to maintain orcompress its own exhaust combustion products to the desired injectionwell pressure. In this configuration, heat accumulated in the engine'scooling system is used, via a heat exchanger apparatus, to transferenergy otherwise lost to heat inlet water before injection into a well.A heat exchanger can also be used to transfer waste heat energy from thecompressor to the water prior to converting it to steam and injecting itinto the hydrocarbon-containing material.

As can be seen from the above inventions, the well-head gas and steamgenerators may be operated on a variety of fuels and oxidizers. Forexample, the generator may be operated on a natural gas/air combustionsystem; a diesel/air combustion system; a gasoline/air combustionsystem; a heavy oil/diluent/air combustion system; or abitumen/diluent/air combustion system. Further, the air used incombustion can be oxygen-enriched or replaced entirely by oxygen toreduce or eliminate unwanted flue gas components, especially nitrogen.The combustion system may use a gaseous fuel system but preferably usesa liquid or solid fuel system when operated underground.

Although the various inventions may be applied to surface wellheads, inthis configuration transmission energy losses remain, and there remainsthe possibility of precipitation and scaling problems in thenon-horizontal portions of the well. In addition, it can be moredifficult to service the well casing in the event of corrosion,precipitation, scaling and the like.

It is therefore preferable, though not necessary, to apply the presentinvention to wellheads installed from an underground workspace where thewellhead is typically within a few to several meters of the reservoir.

Finally, the present invention allows the use of large horsepower,high-efficiency boilers and engines to produce the quantities andqualities of steam necessary to operate SAGD wells capable of producingseveral hundred barrels of oil per day.

The following definitions are used herein:

It is to be noted that the term “a” or “an” entity refers to one or moreof that entity. As such, the terms “a” (or “an”), “one or more” and “atleast one” can be used interchangeably herein. It is also to be notedthat the terms “comprising”, “including”, and “having” can be usedinterchangeably.

A blow out preventer or BOP is a large valve at the top of a well thatmay be closed if the drilling crew loses control of formation fluids. Byclosing this valve (usually operated remotely via hydraulic actuators),the drilling crew usually regains control of the reservoir, andprocedures can then be initiated to increase the mud density until it ispossible to open the BOP and retain pressure control of the formation.Some can effectively close over an open wellbore, some are designed toseal around tubular components in the well (drillpipe, casing or tubing)and others are fitted with hardened steel shearing surfaces that canactually cut through drillpipe.

A Christmas tree (also Subsea Tree or Surface Tree) in petroleum andnatural gas extraction, a christmas tree is an assembly of valves,spools and fittings for an oil well, named for its resemblance to adecorated tree. The function of a christmas tree is to both prevent therelease of oil or gas from an oil well into the environment and also todirect and control the flow of formation fluids from the well. When thewell is ready to produce oil or gas, valves are opened and the releaseof the formation fluids is allowed through a pipeline leading to arefinery, or to a platform or to a storage vessel. It may also be usedto control the injection of gas or water injection application on anone-producing well in order to sustain producer volumes. On producingwells injection of chemicals or alcohols or oil distillates to solveproduction problems (such as blockages) may be used.

A downhole steam generator as used herein is a steam generator that isinstalled in the bore of a well.

A drilling room as used herein is any self-supporting space that can beused to drill one or more wells through its floor, walls or ceiling. Thedrilling room is typically sealed from formation pressures and fluids.

A hydrocarbon is an organic compound that includes primarily, if notexclusively, of the elements hydrogen and carbon. Hydrocarbons generallyfall into two classes, namely aliphatic, or straight chain,hydrocarbons, cyclic, or closed ring, hydrocarbons, and cyclic terpenes.Examples of hydrocarbon-containing materials include any form of naturalgas, oil, coal, and bitumen that can be used as a fuel or upgraded intoa fuel. Hydrocarbons are principally derived from petroleum, coal, tar,and plant sources.

Hydrocarbon production or extraction refers to any activity associatedwith extracting hydrocarbons from a well or other opening. Hydrocarbonproduction normally refers to any activity conducted in or on the wellafter the well is completed. Accordingly, hydrocarbon production orextraction includes not only primary hydrocarbon extraction but alsosecondary and tertiary production techniques, such as injection of gasor liquid for increasing drive pressure, mobilizing the hydrocarbon ortreating by, for example chemicals or hydraulic fracturing the well boreto promote increased flow, well servicing, well logging, and other welland wellbore treatments.

A liner as defined for the present invention is any artificial layer,membrane, or other type of structure installed inside or applied to theinside of an excavation to provide at least one of ground support,isolation from ground fluids (any liquid or gas in the ground), andthermal protection. As used in the present invention, a liner istypically installed to line a shaft or a tunnel, either having acircular or elliptical cross-section. Liners are commonly formed bypre-cast concrete segments and less commonly by pouring or extrudingconcrete into a form in which the concrete can solidify and attain thedesired mechanical strength.

A liner tool is generally any feature in a tunnel or shaft liner thatself-performs or facilitates the performance of work. Examples of suchtools include access ports, injection ports, collection ports,attachment points (such as attachment flanges and attachment rings), andthe like.

A manned excavation refers to an excavation that is accessible directlyby personnel. The manned excavation can have any orientation or set oforientations. For example, the manned excavation can be an incline,decline, shaft, tunnel, stope, and the like. A typical manned excavationhas at least one dimension normal to the excavation heading that is atleast about 1.5 meters.

A mobilized hydrocarbon is a hydrocarbon that has been made flowable bysome means. For example, some heavy oils and bitumen may be mobilized byheating them or mixing them with a diluent to reduce their viscositiesand allow them to flow under the prevailing drive pressure. Most liquidhydrocarbons may be mobilized by increasing the drive pressure on them,for example by water or gas floods, so that they can overcomeinterfacial and/or surface tensions and begin to flow. Bitumen particlesmay be mobilized by some hydraulic mining techniques using cold water.

Primary production or recovery is the first stage of hydrocarbonproduction, in which natural reservoir energy, such as gasdrive,waterdrive or gravity drainage, displaces hydrocarbons from thereservoir, into the wellbore and up to surface. Production using anartificial lift system, such as a rod pump, an electrical submersiblepump or a gas-lift installation is considered primary recovery.Secondary production or recovery methods frequently involve anartificial-lift system and/or reservoir injection for pressuremaintenance. The purpose of secondary recovery is to maintain reservoirpressure and to displace hydrocarbons toward the wellbore. Tertiaryproduction or recovery is the third stage of hydrocarbon productionduring which sophisticated techniques that alter the original propertiesof the oil are used. Enhanced oil recovery can begin after a secondaryrecovery process or at any time during the productive life of an oilreservoir. Its purpose is not only to restore formation pressure, butalso to improve oil displacement or fluid flow in the reservoir. Thethree major types of enhanced oil recovery operations are chemicalflooding, miscible displacement and thermal recovery.

A seal is a device or substance used in a joint between two apparatuseswhere the device or substance makes the joint substantially imperviousto or otherwise substantially inhibits, over a selected time period, thepassage through the joint of a target material, e.g., a solid, liquidand/or gas. As used herein, a seal may reduce the in-flow of a liquid orgas over a selected period of time to an amount that can be readilycontrolled or is otherwise deemed acceptable. For example, a sealbetween sections of a tunnel may be sealed so as to (1) not allow largewater in-flows but may allow water seepage which can be controlled bypumps and (2) not allow large gas in-flows but may allow small gasleakages which can be controlled by a ventilation system.

A shaft is a long approximately vertical underground opening commonlyhaving a circular cross-section that is large enough for personneland/or large equipment. A shaft typically connects one underground levelwith another underground level or the ground surface.

Steam flooding as used herein means using steam to drive a hydrocarbonthrough the producing formation to a production well.

Steam stimulation as used herein means using steam to heat a producingformation to mobilize the hydrocarbon in order to allow the steam todrive a hydrocarbon through the producing formation to a productionwell.

A tunnel is a long approximately horizontal underground opening having acircular, elliptical or horseshoe-shaped cross-section that is largeenough for personnel and/or vehicles. A tunnel typically connects oneunderground location with another.

An underground workspace as used in the present invention is anyexcavated opening that is effectively sealed from the formation pressureand/or fluids and has a connection to at least one entry point to theground surface.

A well is a long underground opening commonly having a circularcross-section that is typically not large enough for personnel and/orvehicles and is commonly used to collect and transport liquids, gases orslurries from a ground formation to an accessible location and to injectliquids, gases or slurries into a ground formation from an accessiblelocation.

Well drilling is the activity of collaring and drilling a well to adesired length or depth.

Well completion refers to any activity or operation that is used toplace the drilled well in condition for production. Well completion, forexample, includes the activities of open-hole well logging, casing,cementing the casing, cased hole logging, perforating the casing,measuring shut-in pressures and production rates, gas or hydraulicfracturing and other well and well bore treatments and any othercommonly applied techniques to prepare a well for production.

A wellhead consists of the pieces of equipment mounted at the opening ofthe well to regulate and monitor the extraction of hydrocarbons from theunderground formation. It also prevents leaking of oil or natural gasout of the well, and prevents blowouts due to high pressure formations.Formations that are under high pressure typically require wellheads thatcan withstand a great deal of upward pressure from the escaping gasesand liquids. These wellheads must be able to withstand pressures of upto 20,000 psi (pounds per square inch). The wellhead consists of threecomponents: the casing head, the tubing head, and the ‘christmas tree’.The casing head consists of heavy fittings that provide a seal betweenthe casing and the surface. The casing head also serves to support theentire length of casing that is run all the way down the well. Thispiece of equipment typically contains a gripping mechanism that ensuresa tight seal between the head and the casing itself.

Wellhead control assembly as used in the present invention joins themanned sections of the underground workspace with and isolates themanned sections of the workspace from the well installed in theformation. The wellhead control assembly can perform functionsincluding: allowing well drilling, and well completion operations to becarried out under formation pressure; controlling the flow of fluidsinto or out of the well, including shutting off the flow; effecting arapid shutdown of fluid flows commonly known as blow out prevention; andcontrolling hydrocarbon production operations.

It is to be understood that a reference to oil herein is intended toinclude low API hydrocarbons such as bitumen (API less than ˜10

) and heavy crude oils (API from ˜10

to ˜20

) as well as higher API hydrocarbons such as medium crude oils (API from˜20

to ˜35

) and light crude oils (API higher than ˜35

).

As used herein, “at least one”, “one or more”, and “and/or” areopen-ended expressions that are both conjunctive and disjunctive inoperation. For example, each of the expressions “at least one of A, Band C”, “at least one of A, B, or C”, “one or more of A, B, and C”, “oneor more of A, B, or C” and “A, B, and/or C” means A alone, B alone, Calone, A and B together, A and C together, B and C together, or A, B andC together.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A and B are schematics of generic steam generators.

FIG. 2 is a schematic of an underground placement of a steam generatorapparatus.

FIG. 3 is a schematic of an alternate underground placement of a steamgenerator apparatus.

FIG. 4 is a schematic of a controllable injector well-head apparatus.

FIG. 5 is a schematic of a steam generator based on a diesel engine.

FIG. 6 is a schematic of an alternate configuration of a steam generatorbased on a diesel engine.

FIG. 7 is a schematic of a steam generator based on a liquid propellantinjector system.

FIG. 8 illustrates a method of pressurizing injection fluids whenoperating underground.

DETAILED DESCRIPTION

The well-head gas and steam generator apparatus of the present inventionmay be operated on a variety of fuels and oxidizers. For example, thegenerator may be operated on a natural gas/air combustion system; adiesel/air combustion system; a gasoline/air combustion system; a heavyoil/diluent/air combustion system; or a bitumen/diluent/air combustionsystem. Further, the air used in combustion can be oxygen enriched orreplaced entirely by oxygen to reduce or eliminate unwanted flue gascomponents, especially nitrogen. The combustion system preferably uses aliquid or solid fuel system when operated underground.

In one configuration, the generator is based on a diesel engine wherethe load on the diesel engine is provided by the work to maintain orcompress its own exhaust combustion products to the desired injectionwell pressure. In this configuration, heat accumulated in the engine'scooling system is used, via a heat exchanger apparatus, to transferenergy otherwise lost to heat inlet water before injection into a well.

In another configuration, the generator may be a robust burner device,such as known in the art, that burns any of a number of gaseous, liquidor solid fuels propellants and can work at reasonably high injectionpressures.

In yet another configuration, the generator may be a robust device thatburns any of a number of liquid propellants and can work at much higherinjection pressures than, for example a diesel engine, and therefore beapplied to formations at pressures as high as about 50,000 psi.

The present invention may be applied to surface wellheads but in thisconfiguration, transmission energy losses remain and there remains thepossibility of precipitation and scaling problems in the non-horizontalportions of the well. In addition, it is more difficult to service thewell casing in the event of corrosion, precipitation, scaling and thelike.

It is therefore preferable to apply the present invention to wellheadsinstalled from an underground workspace where the wellhead is typicallywithin a few to several meters of the reservoir.

Finally, the present invention allows the use of large horsepower,high-efficiency engines to produce the quantities and qualities of steamnecessary to operate SAGD wells capable of producing several hundredbarrels of oil per day.

As described in “Thermal Recovery of Oil and Bitumen”, Roger M. Butler,ISBN 0-9682563-0-9, 2^(nd) Printing by GravDrain, Inc. Calgary, Alberta1998, there has been a significant effort to develop downhole steamgenerators for oil field steam generation. One of the main advantagesseen for this approach is the reduction of well-bore heat losses and,because of this, improved economics for production in very deepdeposits.

There are two basic approaches:

-   1. Low-pressure combustion, in which the downhole combustion is    carried out at relatively low pressure and in which the flue gas    products are vented up the injection well. This approach requires a    heat exchanger down the well to isolate the low-pressure combustion    zone from the high-pressure steam.-   2. High-pressure combustion, in which the products of combustion are    mixed directly with the steam and pass into the reservoir to be    collected at the production or collector wells.

An important possible variation of the second approach involves the useof oxygen-enriched air or primarily oxygen rather than air for thecombustion. This also has the potential advantage that the resultinghigh concentration of carbon dioxide may improve the effect of the steamin recovering oil.

A major advantage seen for the use of downhole steam generators with thedirect injection of the flue gas into the reservoir is that the sulphurand nitrogen oxides can be absorbed in the reservoir, either as anionsin the water or by the rocks directly and flue gas scrubbing is avoided.An example is a high-pressure downhole steam generator developed bySandia National Laboratories in the DOE “Deep Steam” project (1982).Another example is a high-pressure downhole generator developed by theChemical Oil Recovery Co. (1982). The Zimpro-AEC steam generator is yetanother device in which steam mixed with flue gas is produced forinjection into a reservoir. Up until now, downhole steam generation hasnot advanced to the point where it is accepted as a commercialalternative. The equipment that has evolved is complicated and noteasily serviceable. Although the use of downhole steam generators maybecome practical for steamflooding, it is unlikely to be so for steamstimulation, where the requirement for large quantities of steam cannotbe met. Steam stimulation typically requires steam generators of severalhundreds to several thousands of horsepower per producing well.

This prior art shows however, that the concept of a downhole steamgenerator that also injects its combustion products can have significantoperational and environmental advantages. However, as noted, they haveproved impractical because they must be large to provide the quantitiesof steam for a typical SAGD well and they would most likely have to beinstalled on the surface near the wellhead where they would be subjectto energy transmission losses before the steam is delivered to thehorizontal portion of the well where the steam is to be injected.

Consider an example of a SAGD operation where a typical producer wellyields 500 barrels of oil per day at Steam-Oil-Ratio (“SOR”) of 3 andwhere the steam is injected at a temperature of 200 C. If the water mustbe heated from room temperature, a surface boiler operating at 85%efficiency with energy transmission losses of 15% to get to thehorizontal portion of the injector well have to generate 34.3 millionBTUs per hour. If 500 barrels per day of heavy crude are produced, thenthe energy content of the produced oil is 135.1 million BTUs per hour.This means that 25% of the recovered energy in the heavy crude (or itsequivalent of another boiler fuel) must be consumed to produce the nextbarrel of heavy crude.

If a steam generator is located at the entrance to the horizontalportion of the injector well and all the generator's produced energyincluding its flue gases are injected into the formation, then thegenerator, assuming 95% overall energy efficiency, will have to generate26.1 million BTUs per hour. This means that 19% of the recovered energyin the heavy crude (or its equivalent of another generator fuel) must beconsumed to produce the next barrel of heavy crude.

Thus a generator located near the horizontal portion of the injectorwell and injecting all its flue gases into the reservoir saves on theorder of 25% of the energy required by a surface boiler and does notrelease flue gases into the atmosphere.

Although the present invention, which also seeks to increase energyefficiency and sequester flue gases into the formation, can be appliedat the surface, it is preferable to apply it to wells installed from ashaft or tunnel in or near the producing formation. In this case, theunderground workspace can be utilized to accommodate generators largeenough to sustain production rates in the range of 100 to 1,000 barrelsper producer well per day.

FIGS. 1A and B are schematics of two types of generic steam generatorssuch as might be located underground for producing steam for injectioninto an injector well. FIG. 1A illustrates an electrically-powered steamgenerator 101. Electrical energy 102 is input as the energy source andwater 104 is input as the mass source. The generator outputs steam 107and possibly some water 108. In addition, some waste heat energy isproduced in the steam generator much of which can be captured using aheat exchanger to preheat all or a portion of the input water 104.Typically an electrically powered steam generator is in the range of 80%to about 90% efficient at converting electrical energy to energy ofsteam for injection into an injector well. With a heat exchanger topreheat the input water, it is possible to convert over about 95% of theinput electrical energy to energy of steam for injection into aninjector well. At such high energy conversion efficiencies the amount ofoutput water 108 is essentially zero. The input electrical energy 102may be obtained, for example, from an external electric generatingsource such as an on-site surface generator facility or distant powergenerating plant.

FIG. 1B illustrates a prime-power steam generator 111 which uses a fuel112 and oxidant 113 to generate power. Water 114 is input separatelyfrom the fuel 112 and oxidant 113 so the mass inputs are water, fuel andoxidant. The generator outputs exhaust gases 116, steam 117 and possiblysome water 118. In addition, waste heat energy is generated in the steamgenerator much of which can be captured using a heat exchanger topreheat all or a portion of the input water 114. Typically a prime powersteam generator can convert about 25% to 45% of the total energy theenergy of combusted fuel into mechanical energy (typically rotatingshaft energy), approximately 25% to 30% to energy of exhaust gases andthe remainder to waste heat produced mainly in the generator coolingsystem. If the exhaust gases 116 are combined with the produced steam117 and water 118, and if the waste heat energy produced in thegenerator cooling system is captured using a heat exchanger to preheatall or a portion of the input water 114, then about 90% to about 95% ofthe energy of combusted fuel can be captured and made available forinjecting energized steam and other gases into an injector well.

Examples of low cost fuel/oxidant combinations are: diesel fuel/air;diesel fuel/oxygen; methane/air; methane/oxygen; various emulsionfuels/air; various emulsion fuels/oxygen; JP4/red fuming nitric acid;and the like.

A principal objective of the present invention is to locate a steamgenerator in close proximity to an injector well-head and to producesteam at high levels of conversion efficiency. If exhaust gases, wasteenergy and some water are captured and controlled, they can be injectedalong with the produced steam so that the final injected mixture is anenergetic gas in the desired temperature and pressure range and with amixture of gaseous constituents compatible with the reservoir geology.Examples of well-head generators will be provided (FIGS. 5, 6 and 7) forcontrolling a high efficiency steam generator so that pressure,temperature, mass and gas constituents can be tailored to conditionsrequired for thermal recovery in a heavy hydrocarbon reservoir.

FIG. 2 is a plan view schematic of an example of a one of a number ofpossible placements for the downhole combustion apparatus of the presentinvention. The interior workspace of a tunnel or shaft is shownenclosed, for example, by concrete walls 201 and an alcove formed bywalls 202. A wellhead apparatus 212, sometimes known as a christmastree, modified for the present invention, is shown secured to the alcovewall 202 by a flange 211. The alcove wall 202 is formed and sealed intothe shaft or tunnel liner. A method of installing such recesses underformation pressure is fully described in U.S. patent application Ser.No. 11/737,578 filed Apr. 19, 2006 entitled “Method of Drilling from aShaft”. The height and widths of the recesses 202 are in the range ofabout 2 meter to about 5 meters. The lengths of the recesses 202 are inthe range of about 4 meters to about 10 meters. Once installed, therecesses 202 serve as the working space for installing, operating andservicing the well-head equipment. In the present invention, thiswellhead apparatus 212 is adapted for use with an injector well wherewater, flue gases and other gases may be injected into a well. Theequipment such as valves 213 can be utilized to help control theinjection process as well as shut down the well so that the downholesteam and flue gas generator can be serviced or replaced. This processof well-head control is described more fully in FIG. 4. In theconfiguration shown in FIG. 2, a generator 221 is shown positioned inthe tunnel or shaft with its steam, flue gas and water outlets (conduits225, 227 and 227) connected to a manifold 231 which is, in turn,attached to the well-head apparatus 212 and controlled by valves asdescribed in FIG. 4. The generator 221 consumes fuel and all themechanical and exhaust energy produced by the generator 221 is injectedthrough manifold 231. In addition, supplementary water may be injectedthrough conduit 234 and optional gases (CO₂ for example) may be injectedthrough conduit 235. The steam, water and other gases from the generatorare mixed in a manifold 231 which is, in turn, attached to the well-headapparatus 212 and controlled by valves. The steam, water and other gasesfrom the generator may be mixed in any combination and then injectedinto the formation (reservoir rock) via injector well 205. It isappreciated that the supplementary water in conduit 234 may routed tothe generator 221 and used as coolant for the generator 221 so that theinjected water is at a higher temperature when injected ultimatelyinjected into well 205. If the water is used as a coolant for thegenerator 221 then it is preferable that the cooling system forgenerator 221 is operable with untreated water. In the event that thegenerator has to be serviced or replaced, then well 205 can be shut inat approximately normal operating pressure and temperature by a methodfurther described in FIG. 4.

FIG. 3 is similar to FIG. 2 except that the generator 321 is placed inan alcove 303 and thus will be out of the general traffic, ventilationducts and utility conduits in the tunnel or shaft. The generator 331 isshown with its steam, flue gas and water outlets (conduits 325, 327 and327) connected to a manifold 331 which is, in turn, attached to thewell-head apparatus 312 and controlled by valves as described in FIG. 4.Conduits 325, 327 and 327 are preferably connected to the well-headapparatus 312 through a hole or holes drilled between alcove 303 and thewell-head recess 302.

FIG. 4 is a schematic of a controllable injector well-head apparatus andillustrates an example of how an injector well can be controlled,serviced or its steam generator replaced while maintaining the injectorwell at operating pressure and temperature. The rate of injection ofsteam and, in some cases, hot combustion products, from a steamgenerator is controlled by the fuel/air input to the steam generator.The output of the steam generator may include steam, some water and somecombustion products which are fed via conduits 401 to manifold 407. Inthe example of FIG. 4, the manifold is shown injecting steam and othergases via valve 424 and residual water by valve 425. The flow ofsupplementary water and optional gases in conduits 402 can also becontrolled from their respective underground or surface storage sourcesby valves. For example, supplementary water is injected into well 404via valve 423 and optional gases, such as for example CO₂, injected intowell 404 via valve 424. The injector well can be shut-in by closingvalve 421 and shutting of the generator and flow of combustion productsby closing valves 424 and 425, and shutting of the flow of optionalsupplementary water and optional gases by closing valves 423 and 426.The upper master valve 422 and lower master valve 421 can also be shut,thus fully and safely shutting in the well. Once this is accomplished,the generator can be serviced or replaced. If necessary, scale andprecipitates can be removed from the well-head apparatus, at least downto master valve 422 or 421.

FIG. 5 is a schematic of a steam/gas generator based on a diesel engine.The apparatus is designed to utilize all of the fuel energy consumed bythe engine and inject all its produced energy and exhaust gases into awell along with water to create high pressure, high temperature steamthat can be used to heat and mobilize heavy oil or bitumen in areservoir. Typically, about 40% to about 45% of the fuel energy suppliedto a diesel is transformed into mechanical shaft energy; about 30%appears as energy of exhaust products and the remainder as heat energyin the cooling system of the engine (these percentages vary somewhatwith the type of fuel used in the diesel).

In this concept, a diesel engine 508 is shown driving a compressor 502via drive shaft 506. The diesel 508 is powered by a fuel supply 516 andoxidant supply 515. The fuel may be diesel fuel, natural gas or anotherfuel, for example, made from a bitumen, heavy oil or bio-feedstock. Theoxidant may be air, oxygen only or oxygen-enriched air. The choice offuel and oxidant changes the mechanical efficiency and mix of exhaustproducts of the engine and so allows some control over the compositionof injected gases. In the present invention, the exhaust 509 from thediesel is routed to the compressor 502 via conduit 504. The compressor502 compresses the exhaust 505 and injects the compressed hot exhaustgases 522 into a well 501 via conduit 503. Treated or untreated water517 is fed through a heat exchanger 518 where it becomes heated from hotwater in a closed cooling system 510 of the engine 508. This heatedwater is injected 521 into the well 501 via conduit 507. Thus, almostall the energy from combustion of the fuel 516/oxidant 515 mixture isinjected into the well 501 where it is mixed with the injected steam andwater.

When the well-head steam generator is a diesel engine that is modifiedto inject its own combustion gases into the injector well, then anapproximately 4,100 horsepower engine would be required to maintain aproduction or collector well of 500 barrels per day, where theSteam-Oil-Ratio is about 3. This well-head system would requireapproximately 6.1 gallons of diesel fuel per minute and 10.4 gallons ofwater per minute. This size of system, while more efficient than used incurrent practice, is much too large to place downhole from a wellinstalled from the surface. If placed on the surface, it would loseabout 15% of its energy in transmission losses and so would have to bestill larger to compensate. So the preferable placement of such agenerator would be in an underground workspace in close proximity to awell-head.

FIG. 6 is a schematic of an alternate configuration of a steam/gasgenerator based on a diesel engine. This configuration is similar tothat of FIG. 5 except an additional heat exchanger 628 is added to acompressor 602 to moderate the temperature of the hot compressed exhaustgases 605 from the engine 608 and to transfer heat from the compressor602 to additional treated or untreated water 617. The water heated incompressor heat exchanger 628 is added to the water heated in engineheat exchanger 608 at junction 619.

FIG. 7 is an example of liquid propellant gun technology adapted to forma downhole water jet that can work against extremely high backpressures. These back pressures can be in the range of about 10,000 psito about 50,000 psi. The liquid propellant jet drill shown in FIG. 7 canbe modified so that it functions like the diesel engine shown in FIGS. 5and 6. The pistons are driven by combustion of a suitable liquidpropellant in chambers 65 and pressure water or steam in chambers 61which is then injected into an injector well. Although not shown, thecombustion products may be exhausted into the injector well to add theirenergy to the process. The liquid propellant water jet drill shown inFIG. 7 was taken from FIG. 5 of U.S. Pat. No. 3,620,313.

Another advantage of the present invention is illustrated in FIG. 8.Since the present invention is preferably practiced underground, water,for example, may be stored in a tank 803 on the surface. The water canbe sent underground via conduit 804 down shaft 805 where it will arriveat the bottom of the shaft 805 with a substantial pressure head. Theseshafts are typically in the range of 100 meters to over 500 meters deepso this represents a water pressure head in the range of about 140 psito about 700 psi. This pressurized water can be fed into an undergroundstorage tank 807 and from there can be injected into a nearby injectorwell with little or no additional pressurizing. This capability can alsobe used for pressurizing liquid or gaseous fuels, if necessary, for aselected generator.

A number of variations and modifications of the above inventions can beused. As will be appreciated, it would be possible to provide for somefeatures of the invention without providing others. For example, largeprior-art gas burners can be used. Other injectors based on, forexample, a free piston engine can also be modified and used to compresstheir own exhaust products. In another variation, exhaust gases otherthan steam can be routed and sequestered in geological repositoriesdistant from the producing reservoir. Before re-routing these gases,energy can be extracted and transferred to heat a water supply using aheat exchanger apparatus. The present invention, in various embodiments,includes components, methods, processes, systems and/or apparatussubstantially as depicted and described herein, including variousembodiments, sub-combinations, and subsets thereof. Those of skill inthe art will understand how to make and use the present invention afterunderstanding the present disclosure. The present invention, in variousembodiments, includes providing devices and processes in the absence ofitems not depicted and/or described herein or in various embodimentshereof, including in the absence of such items as may have been used inprevious devices or processes, for example for improving performance,achieving ease and\or reducing cost of implementation.

The foregoing discussion of the invention has been presented forpurposes of illustration and description. The foregoing is not intendedto limit the invention to the form or forms disclosed herein. In theforegoing Detailed Description for example, various features of theinvention are grouped together in one or more embodiments for thepurpose of streamlining the disclosure. This method of disclosure is notto be interpreted as reflecting an intention that the claimed inventionrequires more features than are expressly recited in each claim. Rather,as the following claims reflect, inventive aspects lie in less than allfeatures of a single foregoing disclosed embodiment. Thus, the followingclaims are hereby incorporated into this Detailed Description, with eachclaim standing on its own as a separate preferred embodiment of theinvention.

Moreover though the description of the invention has includeddescription of one or more embodiments and certain variations andmodifications, other variations and modifications are within the scopeof the invention, e.g., as may be within the skill and knowledge ofthose in the art, after understanding the present disclosure. It isintended to obtain rights which include alternative embodiments to theextent permitted, including alternate, interchangeable and/or equivalentstructures, functions, ranges or steps to those claimed, whether or notsuch alternate, interchangeable and/or equivalent structures, functions,ranges or steps are disclosed herein, and without intending to publiclydedicate any patentable subject matter.

In one configuration, a heat exchanger is used to transfer heat from theengine to pre-heat water prior to converting it to steam and injectingit into the hydrocarbon-containing material.

In one configuration, a used to transfer waste heat energy from thecompressor to the water prior to converting it to steam and injecting itinto the hydrocarbon-containing material.

1-16. (canceled)
 17. A hydrocarbon production system, comprising: (a) adiesel engine; (b) a compressor; (c) a drive shaft interconnecting thediesel engine to the compressor; and (d) a conduit transporting anexhaust gas of the diesel engine to the compressor for injection, by aninjection well, into a hydrocarbon-containing material to mobilize thehydrocarbons.
 18. The system of claim 17, further comprising a heatexchanger is in thermal communication with the engine to heat water,using waste heat from the engine, for introduction into thehydrocarbon-containing material.
 19. The system of claim 17, wherein thegenerating device comprises a heat exchanger in communication with thecompressor and the water to transfer heat from the compressor to thewater and wherein the heated water is introduced into thehydrocarbon-containing material.
 20. A hydrocarbon production method,comprising: (a) operating a diesel engine to produce an exhaust gascomprising carbon oxides and a rotating drive shaft; (b) operating acompressor, by the rotating drive shaft, to form a compressed gas, thecompressed gas comprising at least part of the exhaust gas from thediesel engine; and (c) introducing the compressed gas into ahydrocarbon-containing material to mobilize the hydrocarbons forproduction.
 21. The method of claim 20, wherein a heat exchanger is inthermal communication with the engine to transfer heat from the engineto the water for introduction of the heated water into thehydrocarbon-containing material.
 22. The method of claim 20, wherein aheat exchanger is in thermal communication with the compressor and thewater to transfer heat from the compressor to the water for introductionof the heated water into the hydrocarbon-containing material.